Produced and flowback water – the challenge, the solution

Terry Beasy

A lot of environmental concerns regarding unconventional oil and gas exploration center around water usage and recycling. From surface evaporation ponds to deep well injections, the industry has long struggled with safe disposal of water that comes as a result of shale exploration. Today we are discussing produced and flowback water purification with Terry Beasy, the Vice-President of Business Development at Heartland Technology Partners.

Monica Thomas (Shale Gas International): Heartland Technology Partners develops and markets proprietary wastewater treatment technology. So in the context of shale gas and oil development this would be flowback and produced water. Can you just briefly explain what these two types of water are and what is the difference between them?

Terry Beasy (Heartland Technology Partners): Flowback water is the water that immediately comes back up the well-casing after the fracturing process of a stranded gas formation. Once the hydraulic fracturing process is completed a percentage of the water used comes back to the surface in the form of flowback water.

Produced water, on the other hand, is water that remains in contact with the gas reservoir or formation in other words downhole – and it becomes saturated over time with the constituents that the reservoir is made of. During production, as the gas comes through the fissures in the formation and up the well bore, it brings a degree of that water back up with it over time as the well produces gas. This stops once gas production ceases – the water will no longer be forced up and will stay in the formation.

MT: And what is the difference between the two types of water in terms of makeup?

TB: To fully understand the chemical makeup of the flowback and produced water, one needs to understand a bit about how these reservoirs we are trying to tap were formed – many years ago.

The once stranded gas reserves are typically a several-year-old underground ocean-bottom. So what happened at some time in the Earth’s evolvement is the magma from a volcano or other interaction flowed over the seafloor during that time and captured some water as well as plant and animal life, along with the salt that may settled out of the seawater, and it encapsulated and stranded that material. This is the gas that we are tapping into now with new drilling technology.

So if you imagine this reservoir as an old seafloor, with animal and plant material degraded and pressure-cooked into methane gas, then you will realize that there must be a very saline environment with trapped water as well. Consequently, when disturb those formations and fracture the rock and you pump some water into these deposits, what happens is that the salt and other items within the formation mixes with fracture water and becomes saturated in the water.

The longer the water is in contact with the formation, typically the higher the salt content of the water.

One way to think about it is in terms of weight. Water in its pure form weighs 8.33 pounds a gallon. Once you start adding minerals to water, the weight will increase. This is why flowback water will often be between 8.1 and 9.6 pounds per gallon – because the amount of salt and other minerals in the formation has weighed up the water so much.

For water that stays in the formation for longer the weight can go up to about 9.6 pounds per gallon or higher.

Now obviously within the salt in the formation there are also other chemicals like barium, strontium or iron and they also get dissolved into the water.

So when we look at flowback water – which stays in the formation for a shorter time – it will be lighter in pounds per gallon and have less downhole constituents than produced water which has remained for longer in the formation. To take iron as an example; typically flowback water would have a lower percentage of the iron content than the produced water.

In other words, flowback water is lighter and relatively cleaner than produced water.

MT: With the produced water, obviously it’s highly saline, but my understanding is that it also contains some radioactive materials like the NORM?

TB: That depends on whether there was radioactive material in the formation or the host rock. There is a great variation across the various plays in various geologic regions. Some areas will be high in sodium chloride, while other will be high in calcium chloride. Some areas will be high in barium, some areas will be relatively low in barium. In the same way, some areas will have a very small amount of radioactive material while others will have a little bit more.

However, in general, the radioactivity of the material – which usually comes up in the form of radium chloride – based on its amount is very, very small.

MT: I understand that with both flowback and produced water there are issues with disposal. Can you tell us more about the challenges that poses?

TB: One thing to understand is that not all flowback and produced water needs to be disposed of. A lot of it can be blended with fresh water and immediately reused in fracking operations.
In the early years of the hydro fracturing process there was a concern that reusing the water that flowed from the formation would impair the formation’s ability to produce gas. Overtime producers began to understand that the water from a well that is flowing back could be put into the next well without affecting the productivity of that well.

MT: Would that be untreated flowback water?

TB: Yes. The untreated flowback water is blended with fresh water and then reused as fracturing fluid. This is to dilute the concentration of chemicals and reduce the salinity of the water.
When it comes to produced water, the only real difference is the amount of salt – or the weight of the water – with the produced water being heavier than flowback water. This is why producers are continuing to evolve the technology of blending it with fresh water and reducing the amount of salt content.

So the industry is continuing to evolve with better water management practices.